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CLR earnings call for the period ending March 31, 2019.

Contents:

Prepared Remarks

Questions and Answers

Call Participants

Prepared Remarks:

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2019 Continental Resources Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Mr. Rory Sabino, Vice President of Investor Relations. Mr. Sabino, you may now begin.

Today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in forward-looking statements. Please refer to the Company's SEC filings for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update forward-looking statements made on this call. Also this morning, we will refer to initial production levels for new wells, which unless otherwise stated, are maximum 24-hour additional test rates. We will also reference rates of return, which unless otherwise stated, are based on $60 per barrel WTI and $3 per Mcf natural gas. Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on the Company's website at www.clr.com.

Prior to beginning the prepared remarks from Harold, Jack and John, I would like to address an erroneous posting from a third-party web hosting service to our corporate website this morning. As some of you may have seen prior to it being removed, our corporate third-party web hosting service inadvertently posted Campbell Soup Company's Analyst Day scheduled for June 13, 2019 on our corporate website. This was a human error unrelated to Continental Resources resulting in the web posting company placing the event in the wrong corporate database after posting our slide deck this morning. This issue was addressed as soon as we were made aware of the third-party error. The correction has been made. And if you look at the corporate event section of the Campbell Soup Company, you will see this event listed in their corporate events. I want to make it abundantly clear, there is absolutely no plan for Continental to host an Analyst Day or any other business update of any kind beyond our normally scheduled quarterly releases.

With that, I will turn the call over to Mr. Hamm. Harold?

Harold G. Hamm -- Chairman and Chief Executive Officer

Good morning, everyone. Thanks for joining us on our call today. Over the past two decades, Continental has captured a very large portion of the best shale resources in the US, which has positioned the Company well for the future. We're benefiting from those first-mover actions by developing these high-quality assets with low best-in-class operating cost. This has been our success formula, which is underscored once again by our team's grown executions in our first quarter results. We saw 2018 become the breakout year we envisioned and 2019 has proven to be equally fulfilling as our teams embrace the strategic shift to unit development within these large project areas all across our broad oil-rich inventory. We've initiated the first year of our five-year vision for sustainable cash flow positive and oil-weighted growth to, again, almost double production. We also remain firmly focused on strong corporate returns.

As you can see on slide six of our investor deck, our corporate returns compete against all industries and nearly doubled the average of the E&P industry. During the first quarter of 2019, we applied our latest technological and cost-efficient completion optimization to legacy areas in three separate geologic domains of the Bakken with tremendous success. On slide eight, you can see the details of these three strategic step-out tests that confirm uplift of well performance across North Carolina and Montana. These results confirm what we've been saying about the Bakken and it continues to get better as the nation's leading high-quality oil play. And our Bakken production grew by more than 15,500 Boe per day for 8% growth quarter-over-quarter. In our closely watched SpringBoard area, the production is forging ahead of forecast, with the first 28 days of April averaging approximately 14,000 barrels of oil per day. The exceptional execution of SpringBoard is another example of our team being the industry leaders in a play we own and Jack will provide details on these significant events later on the call.

Next, Continental teams delivered the low best-in-class LOE cost of $3.59 per Boe. Recall, we are a two-stream reporting company and these low production costs are almost unheard of for a company our size and for our oil-weighted production mix. In our Oklahoma region, our drilling and completion crews produced even faster cycle times by lowering drill days and (inaudible) reaching current technical limits in drilling, giving us the option of further reducing rig activity later on in the year. This is the definition of efficiency and excellence that our teams at Continental continue to achieve every day. Oil differentials have improved as planned for added pipeline capacity materialized from the Bakken. Additionally, WTI has narrowed the spread between Brent pricing as more pipeline infrastructure is being readied to deliver domestic light sweet crude to the international market.

Prior to concluding, I would like to highlight our team's success in acquiring minerals, which is ahead of schedule, underscoring our strong execution. Public equity markets continue to recognize the value creation of mineral strategies. We believe our approach is a unique vehicle for enhancing shareholder value and returns, as we continue to capture minerals under our existing drill schedule. We look forward to providing the market further updates on the long-term benefits of this relationship, which we believe may carry multi-billion dollar potential for the Company. All of these achievements have been realized to allow to deliver the last part of our success formula and that is net earnings of $187 million for the quarter.

In conclusion, if you turn to slide 13, you will see that there is no other management team more aligned with shareholders. This is not only across the E&P universe, but also the broader market. The successful formula at Continental is simple, a powerful oil-weighted inventory coupled with industry-leading costs equals sustainable cash flow positive growth and returns that compete across the market.

Now, I'll turn the call over to Jack Stark for further detail.

Jack H. Stark -- President

Thank you, Harold, and good morning, everyone. I want to thank you for joining us on our call. Our Bakken assets delivered another outstanding quarter with production up an impressive 24% year-over-year. We completed another 55 wells that flowed at an average initial rate of 2,300 Boe per day and 80% of the production was oil. As you know, we have moved to multi-zone unit development at Bakken, utilizing our optimized stimulation technology. Since early 2017, a total of 194 optimized development wells have been completed in 23 separate units and the results have been outstanding. In fact, the entire 194 development well program paid out in the first quarter of 2019. Wells in the top-10 performing units are projected to deliver an average rate of return of approximately 100%. The location of these units are shown on slide seven with the top-10 performing units highlighted in red. The key takeaways here are, one, outstanding results are being realized across a broad cross-section of our acreage, and two, multi-zone unit development of our Bakken assets is delivering results as advertised.

Now, as Harold mentioned, the big news for the Bakken this quarter is the results from three strategically placed step-out wells announced yesterday. These three wells prove our optimized completion technology, continues to uplift well performance from the Southern extent of our acreage in North Dakota all the way out into Montana. As expected, these three wells are outperforming nearby legacy wells by 80% to 110% during the first 60 days and preliminary estimates show these wells are delivering up to 100% rates of return. This is great news for our shareholders as we can confidently say that the value and the performance of our inventory of approximately 4,000 Bakken wells continues to grow. We can also say that the core of the Bakken, as many like to call it, just got bigger. The location of these three wells can be seen on slide eight. In Montana, the Baird Federal flowed at an initial rate of 1,680 Boe per day and 85% was oil. The Burian located in Southern Billings County, North Dakota flowed at an initial rate of 2,400 Boe per day and 80% was oil. In East Central Williams County, North Dakota, the McClintock flowed at an initial rate of 2,440 Boe per day and 80% was oil.

Now, let's move south into Oklahoma, where we have more great results to share. As Harold mentioned, production growth in our SCOOP SpringBoard project is running significantly ahead of schedule. Production for the first 28 days of April has averaged approximately 14,000 net barrels of oil per day, only 2,500 barrels shy of the 16,500 barrels of oil per day we had been targeting by the third quarter. Our current projections show that SpringBoard oil production is likely to reach 18,000 barrels per day in the third quarter. This outperformance is directly tied to our cycle time improvements and higher early time well performance.

This quarter, we announced our first Woodford completions in SpringBoard and the results have been excellent. The six Woodford completions highlighted on slide 10 averaged 1,660 Boe per day per well and 75% of the production was oil. Over time, these unit wells are outperforming our legacy 1.5 million Boe parent type curve for the Woodford oil window. This reflects the performance uplift expected from today's larger stimulation and validates the current plans to develop the Woodford with five to six wells per unit. Our Springer development in SpringBoard is proceeding as scheduled. We have drilled 25 to -- of the 31 Springer wells planned for rows 2 and 3 and completion work is under way. We expect to have results from rows 2 and 3 by our next earning call, but I can say that early rates from a couple wells that just started pulling back look solid.

In Project SpringBoard as a whole, we currently have 39 wells producing, 30 -- 33 wells completing and nine rigs drilling ahead. I want to point out that our rig count in SpringBoard is down by three rigs from last quarter. Cycle time improvements we have realized in the project are allowing us to achieve our objectives for the year, with 25% fewer rigs. There's no better proof of the efficiency gains our teams have achieved than that. These three rigs have been redeployed to other SCOOP assets. In STACK, we brought on two outstanding fully developed units in the Meramec condensate and oil windows. The five-well Tolbert unit flowed at an impressive combined rate of 5,900 barrels of oil per day and 77 million cubic feet of gas per day or 3,740 Boe per day per well. This two-mile unit included three wells in the Upper Meramec and two wells in the Lower Meramec. Like our previous Simba and Boden units, the total unit wells on average are outperforming our parent type curve for the over-pressured condensate window of STACK. In the over-pressured oil window, we finished development of the three-well Lugene unit, which consisted of three one-mile wells. These three wells flowed at a combined initial rate of 4,620 barrels of oil per day and 28 million cubic feet of gas per day or 3,090 Boe per day per well. Lugene wells are strong producers, slightly outperforming our two-mile unit type curve for the over-pressured window during our first 60 days.

In addition to our unit development activity, we recently completed our first three-mile Meramec lateral in STACK called the Blondie 1-6-7-18XHM. The well flowed at an initial rate of 2,460 barrels of oil per day and 5.6 million cubic feet of gas a day or 3,400 Boe per day. As we continue to deliver strong repeatable results in STACK, I think it's worth noting what is driving these results. Our success is driven primarily by geology. As we have always said, our acreage is located in the over-pressured window STACK and underlain by some of the thickest and best-quality Meramec reservoir in STACK. To illustrate, slide 12 shows all the Meramec wells completed from January 15, 2015 to-date, that produced at an average initial 30-day rate of 1,500 Boe per day or more based on public records. Continental wells are highlighted in red on this slide. Two things are evident on this map. First is that the vast majority of the high-performing wells are found in the over-pressured window. Second is the correlation between the superior performance and Continental's acreage position is evident. In addition to being in the right geologic zip code, proper well density is also critical to unit development and well performance and we established that quite a while ago.

In addition to the excellent well performance we're experiencing in both SCOOP and STACK, our operating efficiencies continue to reduce cycle times and costs. As I mentioned before, our cycle times in SpringBoard have come down dramatically with our Springer drilling cycle times down nearly 30% from row 1. Total completed well cost for our Springer -- our SpringBoard, Springer and Woodford wells are down almost $500,000 per well from our original 2019 budgeted costs. In STACK, our drilling cost per lateral foot have come down almost 16% this year. These operating capital efficiencies are materially accelerating our pace of development and reducing costs. This, in turn, provides added flexibility for the allocation of rigs, capital and production growth. John will get into this further, but I want to thank our teams for their hard work and ingenuity that keeps Continental the lowest cost producer among our oil-weighted peers.

Thank you, Jack. We are off to a great start in 2019 with first quarter results reflecting the strength of our team's execution. As we released last night, our earnings solidly beat consensus, driven in part by strong oil-focused production with significantly improved oil differentials. First quarter production came in at more than 332,000 Boe per day, oil production for the quarter was approximately 194,000 barrels per day, up 4% fourth -- over fourth quarter 2018. As we predicted last quarter, we have seen improvements to our corporate oil differential in the first quarter coming in at a much improved $4.77 per barrel, toward the lower end of our 2019 guidance. Our current expectation is for production and oil differentials to remain strong into and throughout the second quarter. Our gas differential came in at an average negative $0.60 for the first quarter, negatively impacted by January and February market conditions. We have subsequently seen significant improvement with March at a much improved negative $0.36. We currently expect full year gas differentials to be within guidance.

In addition to strong production and oil differentials, our cost structure continues to be among the very best of our industry, as represented on slides four and five in our investor deck. In the first quarter, we remained within or better than all of our cost guidance measures. G&A and production expense both came in below our guidance range, with an oil-weighted production expense of $3.59 per Boe and total G&A of $1.60 per Boe. Continental is consistently among the very best in margins generated by low cash cost and high return oil-weighted assets. We are pleased with our performance against these guidance measures. As we proceed through the balance of the year, we will continue to assess our results and we will update guidance as appropriate. Obviously, we are performing exceptionally well versus guidance.

Regarding CapEx, as Jack mentioned, we have seen rapid improvement in our cycle times in both drilling and completions during the first quarter and our teams are performing at a very efficient level. These efficiency gains result in lower well cost and improved rates of return, while at the same time, increasing the number of wells that we are able to drill and complete with the static rig and completion crew count. Therefore, our first quarter 2019 CapEx came in higher than originally budgeted as we were able to spread an incremental six net wells and had first production on an additional eight net wells versus our original budget. Our current plan is unchanged, targeting the $2.6 billion capital budget for the year. Our higher level of spend in the first quarter is a product of our success in mineral acquisitions and operational efficiencies, as I just covered.

We do recognize that oil prices are well above the $55 price at which we budgeted and provided guidance. At $55, we were projecting free cash flow of $500 million to $600 million. Recall that every $5 change in WTI is about $325 million in free cash flow for the year. We are now through a quarter of the year, and with the rise in oil prices, we are tracking toward $1 billion of free cash flow for 2019. We are strongly committed to meeting our corporate objectives and this incremental level of cash flow will enable us to accelerate our debt reduction timing, reducing net debt to $5 billion or below this year, assuming current commodity prices. We can easily adjust to be within our $2.6 billion budget for 2019, while performing well on all of our other guidance. If these higher prices are sustained, we will make a determination of the proper use of additional cash flow later in the year. Any use of the incremental cash will be prioritized toward debt reduction and building free cash flow.

As mentioned earlier, our pace of mineral acquisitions is going well in our new venture with Franco-Nevada. During the first quarter, we closed the mineral acquisitions of $51 million. Recall that Franco-Nevada covers 80% of the acquisition cost and we split revenues based on hitting performance targets. As we are acquiring in areas we expect to develop near-term, we expect a 50-50 revenue split. The acceleration in SpringBoard production benefits our minerals portfolio, as we own 19 -- approximately 19% of the mineral royalties underlying CLR's leasehold position in SpringBoard. In summary, with strong corporate returns, low-cost operations and high-quality assets, we remain confident in our 20 outlook -- 2019 outlook to deliver 13% to 19% year-over-year oil production growth alongside exceptionally strong free cash flow, favorably benefited by recent improvements in crude oil prices.

With that, we're ready to begin the question-and-answer session of our call and we will turn it back over to the operator to take questions. Thank you for your time this morning.

John, I think the first question, John, for you, if I may, the tracking toward $1 billion of free cash. I've got kind of multiple pieces to this question I guess because your costs are clearly trending lower, although you haven't chosen to change that guidance yet. Your differentials are running better, and obviously, your pace of development through the course of the year looks like its running ahead of schedule as well. So I just want to pool all that together and to say that your last comment was you're going to remain committed to reducing debt and maximizing free cash flow, but should I interpret that then that you're not changing the $2.6 billion capital budget irrespective of all the great things you've done so far this year? Because clearly, you've got the flexibility to if you chose it?

We're comfortable where we're at. We're four months into the year. And as you referenced on guidance, we're doing extremely well on a lot of that. We'll continue to monitor that and update as we go throughout the year. We don't see any reason to adjust the CapEx budget today. We're doing -- like I said, doing exceptionally well and we're going to deliver strong results with that.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Just to -- sorry, John, to labor on this point, but because you're running ahead of schedule, obviously, you're spending more earlier in the year. So if you continue to develop, would that mean you would slow down to stay within capital or -- you see what I mean because there's obviously going to be upward pressure because of your efficiency gains, not so much because you're spending more. Would you slow things down to stay within the $2.6 billion or how should we think about that?

Yeah. I think we can certainly moderate our level of activity throughout the year. We can also -- we also have different working interest in projects. We don't have a lot of term contracts. The one -- of the term rig contracts we've got, 90% of them expire this year. Even where we're at today and just projecting out, consistent throughout the rest of the year, we wouldn't be over that much, so it's not a large stretch for us to adjust and so I think we're very comfortable where we're at today.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks. My follow-up is for Jack. Hopefully, just a quick one. Jack, I'm not sure I interpret that the comment on the drilling -- the backlog of all the inventory in the Bakken correctly. Your step-out wells are clearly bringing on what were previously second-tier or non-core areas into it as you put expanding the core, but what was included in the 4,000 locations? Was that already assuming that this acreage was prospective or I guess another way to ask it is how heavily risked was your acreage before and how risked do you see it going forward now? I'll leave it there. Thanks.

Jack H. Stark -- President

Yeah. Good question, Doug. And our 4,000 locations that we've talked about still stands. It did include these areas. We always saw these as being part of our portfolio to ultimately develop, but what's happened here is as a result of our optimized completions, the value of that inventory has been uplifted and uplifted significantly. And so this suggests a very -- just a methodical continued process here that we're going through to demonstrate that our optimized stims are uplifting the value all the way across the field. And if you look at that slide on page eight as well, you notice that there is just the constant growing pattern of wells that have exceeded matter, exceeded 100,000 barrels in the first 90 days and so this is a phenomenon that's happened across the whole field. It's just -- historically, the Bakken has been under-stimulated, and now that we're actually properly stimulating the zone, we're really starting to unleash the true potential of the play.

Good morning, everyone. Really, really strong quarter in light of even some really harsh weather. Could you just talk about how you see the pace of volumes progressing as, I guess, SpringBoard ramps up and it seems like you have a lot more momentum in the Bakken than I would have anticipated?

Harold G. Hamm -- Chairman and Chief Executive Officer

Yeah. Drew, that's a good question. Our teams, we've been working up there a long time. All these guys working -- that's where they live, that's what they deal with. And so we handle the weather situation better than most companies and -- due to that, so they get it done very well. We are seeing in the -- production increase, as we go forward, coming out of that first quarter. So second half, we'll see additional production come on and you referenced SpringBoard and certainly that's going to add a great deal to the second quarter production, and particularly in the second half here.

Jack H. Stark -- President

We've got a slide on slide number nine that gives you a little bit of update on SpringBoard also, we're showing instead of 16,500 in the third quarter this year, we're expecting to be 18,000 or so, so we are uplifting that. You're seeing some improvement there, and as Harold indicated, we're showing sequential growth in production throughout the year. And again, as you know, it's very much focused on oil, so we feel very good about where we're at.

Drew Venker -- Morgan Stanley -- Analyst

Understood. Thanks for the detail. And as a follow-up on the Bakken step-out program, can you please talk about how many wells and what areas you'd plan to be testing later this year?

Jack H. Stark -- President

Well, Drew, we've done these. If you notice on that map on page eight, we've done -- basically is we've drove well, a well as far south as we could and as far west as we could. So we feel pretty good that the areas in between are going to respond. And so -- and we are pushing it further to north and we'll continue to do that as well, but our attempt here was to demonstrate as quickly as possible that this technology that we're using is uplifting the performance all across the play. And I think you can't ask for any better evidence than what we've shown here right now with these extreme west and south and basically the northerly step-outs that are delivering just pretty much as expected, outperforming legacy wells and really just performing as we've seen all these optimized teams perform across the play.

Harold G. Hamm -- Chairman and Chief Executive Officer

And Drew, this evolution, you've watched, has really occurred over the past three years. As we've moved forward, worked with this technology improvement and optimization, so long back end of it, some of these -- legacy area is certainly is fun to apply the latest and see how this turns those areas on. So it's really very exciting.

Drew Venker -- Morgan Stanley -- Analyst

And is the authorized completion approach for these step-out areas similar in your process as to the rest of the play?

Jack H. Stark -- President

Yeah. Drew, they are. They -- I mean, we're -- they vary in design, obviously, but -- for the area, but what we're talking about is basically closer per cluster spacing and basically more stages in proppant than we've historically used out in these areas. And so it's really the same model, applying it very effectively in each of these areas and couldn't be more pleased with the outcome that we've got.

Drew Venker -- Morgan Stanley -- Analyst

Excellent. Thanks.

Harold G. Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

Thank you. Our next question comes from Arun Jayaram with JPMorgan.

Arun Jayaram -- JPMorgan -- Analyst

Yeah. Good morning. John, I wanted to talk to you a little bit about your full year oil guide. This quarter, you hit just below the midpoint of that 190,000 to 200,000 range and we think about the April production that you highlighted in Project SpringBoard. Could you give us a feel or maybe a range for 2Q oil volumes corporatewide?

Yeah. I don't have exact numbers in front of me. We are continuing to show growth and maybe a little flatter here in the mid part of the year. And as we get out into the latter summer, early fall, it starts to turn back up again. And that's just project timing. We -- I think we talked about -- a little bit about that back in the February call. We're on these large pads with these large number of units coming on. So probably a little flatter here, but then turning up nicely.

Arun Jayaram -- JPMorgan -- Analyst

Okay. And similar question on CapEx. I think last quarter, you highlighted how CapEx have trend down, I believe, in 2Q, moved up a little bit on the project timing in Q3 and kind of moved down in Q4. Can you give us a little bit more color on your thoughts on perhaps 2Q CapEx with and without mineral spend?

I think you did a pretty nice job there. That is what we see, second and third quarter coming down relative to the first quarter, fourth quarter down from both of those second, third, probably relatively consistent with each other. Obviously, without mineral spend, you're nicely below the $700 million. So I think we'd feel very good. And I think you know this, but the key on the mineral spend is that 80% of that's a pass-through because of our carry relationship.

Arun Jayaram -- JPMorgan -- Analyst

Great. And just my final question is, where are we in the steps to kind of -- to extract values from minerals? Are you still comfortable with the $125 million of spending without the reimbursement this year?

If you like to like -- look to last year, we went in and adjusted the -- the $125 million is a per-year type target, but we have the ability with our partner if we both choose to to move amounts around within that program. So for instance, in the fourth quarter last year, we carried some from -- some of the amounts in the last year, we backed out of that and added back in there. We could clearly do that in '19. It's all opportunity-driven and it's an economic opportunity as well as geology and our development plans. So if need be, we can make adjustments in conjunction with our partner if we chose to. Right now, we're good where we're where at.

Thank you. Our next question comes from John Aschenbeck with Seaport Global.

John Aschenbeck -- Seaport Global -- Analyst

Good morning, everyone, and thank you for taking my questions.

Jack H. Stark -- President

Certainly.

John Aschenbeck -- Seaport Global -- Analyst

So for my first one, I just kind of had a follow-up to a question from earlier in the call. I was wondering, how we should think about just the general progression on capital spending throughout the remainder of the year? Thanks.

Yeah. I think the last question was add up. Second and third quarter down from the first quarter, the fourth quarter down from there. It's -- right now, it's the lowest of the year. And with the -- excluding minerals, they're both below $700 million. Even with minerals, we should be below that. So we're in good shape.

I think the key is the $2.6 billion for the year, we're retaining as our budget plan for the year.

John Aschenbeck -- Seaport Global -- Analyst

Okay. Great. Appreciate the clarification there. Yeah. And so for my follow-ups, just industry consolidation has obviously been the dominant topic in the industry as of late. And with that, I'd just love to get your general thoughts on how you view the current M&A environment and your thoughts on what Continental's role, if any, is likely to be as an industry consolidator, especially if I just think of Continental historically has been a company that's grown considerably through exploration as opposed to M&A? Thanks.

Harold G. Hamm -- Chairman and Chief Executive Officer

Well, it has and we sort of have grown this Company through exploration, but strategic bolt-ons have always been of interest to us. And just this last quarter, we've done several of those and we consistently do that within core areas of where we operate. I might tell you that there is an unusual amount of interest with acquisitions. John, I think across the sector -- the E&P sector I'm talking about, there's realization that companies are undervalued and certainly have seen a correction with some of that just recently. So anyway, we continue looking at strategic opportunities that come around and we've seen several of those recently.

John Aschenbeck -- Seaport Global -- Analyst

Okay, great. I appreciate the detail and thank you for the time.

Harold G. Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

Thank you. Our next question comes from Jeanine Wai with Barclays.

Jeanine Wai -- Barclays -- Analyst

Hi. Good afternoon, everyone.

Jack H. Stark -- President

Hello.

Jeanine Wai -- Barclays -- Analyst

Hello. So I just wanted to follow up on Doug's earlier question on the CapEx budget and use of the free cash flow. Assuming that oil prices stay constructive, in the past you've talked about perhaps getting an early start on activity in the following year. And so I was just wondering, are you thinking about that differently this year kind of given the narrative shift in E&P and no longer prioritizing or rewarding growth? So for example, I know that the dividend conversation going on went to get closer to your net debt target, but with any additional free cash flow, are you aiming more likely now to go kind of below that $5 billion target with any extra free cash flow versus adding activity because I think you can reduce debt down to $4.2 billion based on what's callable and I know there's a delicate balance kind of between getting on return of capital versus progressing to a low-debt model where you can defend the dividend at any oil price? So I just kind of wanted to check in on this.

Harold G. Hamm -- Chairman and Chief Executive Officer

Sure. Well, appreciate that, Jeanine. Obviously, there is an opportunity out there, if we choose to go with dividends, certainly it would open the door to an area that the Company hadn't participated in with investors. So that is out there and we will be looking at that very closely, but we do want to get down to the point that we've talked about with debt and so we could accelerate that prior to 2020.

Yeah. You may have noted in my script, I said $5 billion or lower. The or lower was added this time. Yes, we expect it -- our target as we go forward, I'm not saying it's necessarily all this year, but we -- that $4.2 billion, we would eventually like to get down to that. We're not putting up that level of cash flow for the nine months remaining this year to get all the way down there, but eventually, we will get down to a much lower than the $5 billion of target. And we've got a lot of options with the great asset base we've got, with debt reductions, with dividends. I think you laid a number of those out very well, setting up outlying years, anything. We're chasing value, we're not chasing just growth for growth through those things. So all of those options are things that can add to value.

Jeanine Wai -- Barclays -- Analyst

Okay. And then my follow-up question, it's more of a housekeeping question. I believe last year's budget had about $600 million of CapEx that was allocated toward wells that wouldn't produce until this year. And I was just wondering, if you can remind us how much of this year's CapEx budget is allocated toward production next year?

Okay. So the total budget for this year is about $2.6 billion, it's not about, it is. The D&C component of that is about $2.1 billion something. Of that, a little bit over $500 million doesn't have first production until 2020. So the level of capital that we're spending in this year budget on D&C with current year production is about $1.6 billion. So I think you may be working toward maintenance capital, numbers are pretty low. So we're in a very good shape to deliver on our plans.

Shifting over to the STACK, what was the genesis behind the three-mile Meramec lateral? And are you planning more in 2019?

Harold G. Hamm -- Chairman and Chief Executive Officer

Well, the genesis was that we -- our operating team felt we could do it and do it very efficiently and it turned out we could and we had a branded quarter -- a branded section that we decided that we just go ahead and develop from the same payout and so was able to do that and we felt like it's a very, very clone area, would produce throughout the entire lateral. And this is a great well out there. We're beyond reporting single wells, have been for a long time, but this is such an exceptional well that we thought everybody ought to know about it. It's in a very good place. Our team did a wonderful job.

Derrick Whitfield -- Stifel -- Analyst

Very good. And perhaps as my follow-up, regarding the Woodford update and Project SpringBoard, the update looks overwhelmingly positive relative to your legacy 1.5 million barrel type curve. Could you remind us of the spacing for the Woodford in this row and if the productivity of the wells exceeded your pre-drill expectations?

Jack H. Stark -- President

Yeah. We're looking at five to six wells per unit in here, typically. And so -- and as you said, the performance of these wells, they've come on early time, come on very strong and what we've done in here is used our latest stimulation technology as compared to our legacy in there, so we're seeing what we would anticipate to get some uplift as a result of that. And also, it's -- I'd say based on these results, over time, it sure is supporting that five to well -- five to six well density.

Derrick Whitfield -- Stifel -- Analyst

That's very helpful. Thanks for your time guys

Harold G. Hamm -- Chairman and Chief Executive Officer

.Thank you, Derrick.

Operator

Thank you. Our next question comes from Neal Dingmann with SunTrust.

Neal Dingmann -- SunTrust -- Analyst

Good afternoon, guys. Jack, maybe just adding on to Derrick's question there, sticking with that -- the Woodford sort of development. Could you talk about just sort of continued expectations or on running the variability I'm looking at, I think prior slides where you looking what you had like specifically with the pile well 24 hours just a little bit higher, I think around 18 or so -- 1,800 or so and a little bit oily. So I'm just wondering overall versus the last you had here, it looks like -- not too far off, but about the same 1,660 with about 75%. So really, my question is kind of expectations for that going forward as far as from an oil percentage and kind of from an IP percent.

Jack H. Stark -- President

Yeah. As you know, we've said the average for the Woodford, we're anticipating on here is about 70% oil and that's because you get from an oilier side on the east side and as you move to the west of the unit, Project SpringBoard, you get a bit more gassier and get into that more condensate window. So you're going to see a gradational change, but the average we're talking about here is going to be in that 70% range.

Neal Dingmann -- SunTrust -- Analyst

Okay. And then size-wise, you're still anywhere, as I said, the pile is a little bit more I think this other closer to a little over 1,800 versus closer to 1,600 expectation. Will that, too, Jack, shift as you go east to west kind of...?

Jack H. Stark -- President

Excuse me, there. Yes. I think that this is a very good outcome in here. These are unit wells that are coming in after a parent well in here and you'd expect to see a bit of degradation, plus, also remember what we've seen in here when we come in and do the density development, there's just a -- these wells have come on a little bit slower with oil because of the amount of basically the stimulation fluid that's been pumped as we're stimulating these wells. It takes just a little while to get that water back out, but boy, when they come back on, they come on strong. So anyway, so we're -- I think this is a fair expectation going forward.

Neal Dingmann -- SunTrust -- Analyst

Okay. And then just lastly, cognizant not having the 2020 out there, obviously, not even yet. Just thoughts when you look forward toward the end of the year next year on reallocation between the Bakken and let's just use the whole entire MidCon because, again, you are getting such fantastic results, obviously, in both these broader plays. So I'm just wondering as you all are stepping back, Jack, you, Harold and the team are sort of looking at it on a longer-term. Does it come down to just simply economics? Does it come down to the amount of inventory? I'm just wondering now when you are on a go-forward, how you think about reallocation or if there will be any between sort of the two broader plays going forward?

Harold G. Hamm -- Chairman and Chief Executive Officer

No, I don't see a lot of difference in reallocation. We've tried to drag it by one year before we project out what CapEx is going to be next year, but we might see the expansion of CapEx the following year, but a lot of things come into it. And we mentioned earlier that we keep an eye on supply and try not to overflow the market as well. So that's several things, as you mentioned, and add that perspective that comes into it.

Jack H. Stark -- President

The beauty of this is that we do have that optionality to move capital around if need to -- need be for whatever reason, but I'd refer you to our five-year projection to look at capital allocation. And there, you can see that, in general, we expect to see about 60% to 65% of our growth over that five-year period coming from the Bakken and I think that pretty well would correlate with -- and that capital range is probably going to be in that maybe 60% -- 50% to 60% probably Bakken -- 60% Bakken.

Neal Dingmann -- SunTrust -- Analyst

Okay. That's what I thought. Okay. Thank you all.

Operator

Thank you. Our next question comes from John Freeman with Raymond James.

John Freeman -- Raymond James -- Analyst

Good afternoon, guys.

Harold G. Hamm -- Chairman and Chief Executive Officer

Hey, John.

John Freeman -- Raymond James -- Analyst

On slide 10, you all show the big cost reductions that you've had and the efficiency gains as you all switch the wellbore design. And last quarter, you all mentioned that you are close to begin testing of a new wellbore design in the STACK. And just curious if that's started and when we may get results or more details on that?

Pat Bent -- Senior Vice President, Drilling

Yeah, John, this is Pat. And yes, we have started that well in STACK. Don't have that PD-ed yet nor completed. And so that should be Q2 and we'll give you some results then.

John Freeman -- Raymond James -- Analyst

Okay. Great. And then just a follow-up question, so a little bit of a follow-up on what Neal was discussing. If I looked at -- just thinking about just the Bakken relative to the five-year plan, are the -- the step-out wells, especially the ones in the west in Montana and then the one that was the extreme southern step-out in the Bakken, do those results -- do you feel those are significant enough to potentially change the allocation of activity within the Bakken relative to the five-year plan?

Jack H. Stark -- President

Sure. It can influence the allocation here as we try to maximize the value of any of these units with the infrastructure that's in place, all those types of things. And so again, what this does is just -- it proves this uplift of performance, expands across our acreage and it gives us just more optionality for development.

Harold G. Hamm -- Chairman and Chief Executive Officer

One thing, John, that I'd throw in there is that we've got other area here in Southern Oklahoma that also is begging for CapEx. It's (inaudible) Woodford and as (inaudible) talked about. And here in the South, I mean, obviously, the results that we've had in the STACK that -- we've got (inaudible) here that is also begging for additional CapEx that's competing with that.

John Freeman -- Raymond James -- Analyst

I appreciate it. Nice quarter guys.

Harold G. Hamm -- Chairman and Chief Executive Officer

Thank you.

Jack H. Stark -- President

Thanks, John.

Operator

Thank you. Our next question comes from Nitin Kumar with Wells Fargo.

Nitin Kumar -- Wells Fargo -- Analyst

Good afternoon. How are you?

Harold G. Hamm -- Chairman and Chief Executive Officer

Doing well. I'm fine.

Nitin Kumar -- Wells Fargo -- Analyst

I just wanted to touch base. John, you mentioned the Bakken differentials being stronger. They've kind of widened out a little bit here early in April. Just your thoughts on what are the dynamics there and how do you -- how should we think about going forward for the year?

I think the Bakken differential obviously improved dramatically. You had a little bit of a blowout in December, but we've seen sequential improvement through the first quarter. April is looking strong as well. We did guide a little bit wider this year relative to last year just taking some of that into account. We're at the low end of that guidance. I think what we're seeing going forward right now continues to be strong and improving differentials. Take -- just think over the next 12 months the amount of takeaway capacity that you've got coming into the Basin. That will continue to benefit it and -- as well and that spread kind of throughout this -- throughout the next few months, the next 12 months. So I think we feel very strong and we'll continue to monitor that and our associated guidance as we go throughout the year. But so far, very good.

Nitin Kumar -- Wells Fargo -- Analyst

Great. And just sticking with the Bakken here, I couldn't help but notice that the step-out well in the Montana. Strong results, obviously, but maybe about two-thirds of your IP is in the core of the Basin in the North Dakota side. What are your well costs out there? That's question one. And then, two, any plans to test Divide County?

Harold G. Hamm -- Chairman and Chief Executive Officer

Well, let's take our Montana first. I mean, the beauty of that area is that also you're only looking at about two-thirds the cost. Is that all the infrastructure in over there. We've got 50,000 or better acreage -- acres there, at least if we don't have too far. I mean, it's just an area that's got the rock that we just need to go develop, it's a very good area. You termed out Divide County, sure. You saw recently that there's a leap toward that area and we've seen some good results out there as well.

Nitin Kumar -- Wells Fargo -- Analyst

Great, thank you.

Harold G. Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

Thank you. Our next question comes from Paul Grigel with Macquarie.

Paul Grigel -- Macquarie -- Analyst

Hi. Just following up on the Bakken there, as you do step-outs. Is there a material difference in well costs as you look at Montana or Southern Billings County, given they're a little bit shallower in the quarter?

Harold G. Hamm -- Chairman and Chief Executive Officer

Yes. I just talked about that on the last question there, but you must not have been on the phone there, but the beauty...

Paul Grigel -- Macquarie -- Analyst

Well, I guess just natural drilling, Harold. Not -- I understand and appreciate the infrastructure and the land cost, but the actual drilling, the D&C cost, is that actually cheaper?

Harold G. Hamm -- Chairman and Chief Executive Officer

Yeah, it's shallower and in both those areas that we just talked about. And so it's -- the drilling cost is cheaper, and certainly, I've mentioned infrastructure. Jack, you might want to add?

Jack H. Stark -- President

Yeah. When you look at Montana, our costs out there are in that $6.5 million to maybe $7 million range. And say that when you get down south there in Billings County, we're doing more in about maybe $7.5 million range there. And so as Harold said, the costs are down substantially there and the performance that we're seeing there is just going (inaudible). I mean, down there in Billings County, I mean, the way that Burian is performing here, we're looking at rates of return 100% or higher on our well there and out there in Baird Federal, I mean, we're looking at -- not going to do our 50% rates of return out there. So I mean, that's really just excellent outcomes in each of these areas and we just have a lot of running room.

Paul Grigel -- Macquarie -- Analyst

Thanks and thanks for bearing with me on the subtlety of trying to get down to beyond just the infrastructure part there. I guess, turning further south to the MidCon. Jack, I think it was you that mentioned the three rigs removed into different parts of the SCOOP. Could you talk with the drilling efficiencies why they're moved there versus maybe other areas you do within the MidCon or Bakken just as you reallocated them around?

Jack H. Stark -- President

Well, they've been moved to other grade areas down there in SCOOP and we're drilling -- you will really get to see some results with some of that activity here down the road. So anyway, it's -- they're all being put to good use.

Paul Grigel -- Macquarie -- Analyst

Okay, thanks so much.

Harold G. Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

Thank you. Our next question comes from Leo Mariani with KeyBanc.

Leo Mariani -- KeyBanc -- Analyst

Hey guys. You certainly did a good job highlighting some of the cost reductions that you've had on the SCOOP wells. I know you're expecting further 7% reduction. I think in your prepared comments, you talked about some efficiency gains in STACK as well. Could you maybe talk a bit more about the well cost progression there in terms of where the costs may have been, say, a few quarters ago, where they are today and kind of where you're expecting those STACK well costs to go later this year?

Pat Bent -- Senior Vice President, Drilling

Sure. I think we've mentioned it the last quarter. But as we explore the (inaudible) design in STACK, we would anticipate an additional $600,000 in savings for those costs. So that again is looking forward. Currently, when you look at downhole tool liability and just lateral total refinement, see our costs drop just through the efficiency gains pad-to-pad perspective.

Leo Mariani -- KeyBanc -- Analyst

Okay. That's helpful. And I guess just over to the Bakken side, certainly, you've had some very nice step-outs here. Wanted to get a sense of whether or not your geologic and economic models are projecting that you guys would continue to see wells that are as strong as you move up north into Divide County or do you think maybe those wells would be closer to some of the rates that you see in Montana versus a few of the more core counties in the Bakken?

Jack H. Stark -- President

Yeah. I think that -- if you go to page eight, I think it's just always interesting to note that there's a green dot up there on the Northeast part of Williams County, always in Divide that that's a well that produced over 100,000 barrels in the first 90 days. And so as we move up in that direction, I do think that we will see average EURs go down. We're -- but I'd also think -- as we talked previously, well costs go down and the returns are the key here in the value creation we're going to be able to get, so I really think that we're going to find that the economics of what we see, as we move further north, we will continue to compete with what we're seeing down south, probably going to be a bit less, little bit higher water cut, but the bottom line is that I still think we're going to have very economic performance up there.

Yeah. Hi. So Harold, since you brought up M&A and some of the things you might have looked at recently, I'm just curious, would they fall more in the tuck-in category or have you been rethinking your approach to corporate large-scale M&A?

Harold G. Hamm -- Chairman and Chief Executive Officer

No. I think these are mostly the tuck-in category, bolt-on, as we call them, strategic stuff within our operating areas, particularly MidCon and maybe more so than Bakken.

Subhash Chandra -- Guggenheim Partners -- Analyst

Got it. Okay. Thank you. And my follow-up is sort of looking a little further down the path here. You'll be done with the Springer wells at SpringBoard by 2020 and -- so some questions have sort of revolved around, you would have peak production at that point from SpringBoard and then what happens in 2021. So I'm curious if the Sycamore-Woodford program takes it forward from there for further growth or is that when others SpringBoards come into play?

Harold G. Hamm -- Chairman and Chief Executive Officer

We have other SpringBoards. We just haven't been pointing that out there lately. We've talked about it, but just hadn't pinpointed it. So -- and most of this is HBP stuff, so that's a good part.

Jack H. Stark -- President

Yeah. My response to it, Subhash, is it's both. It is Woodford and Springer, other SpringBoard projects. I mean, because you're going to find that Woodford (inaudible) definitely has a potential to expand. And obviously, we have other sites on additional SpringBoard activity.

Harold G. Hamm -- Chairman and Chief Executive Officer

But when you look at the five-year plan, you see that there's not a lapse in production out there.

Hi. Good afternoon. Quick question about the first quarter oil volumes. Just wondering, if there are any special one-time assessments? As strong as it was, I -- given the uptick in Bakken and the SpringBoard volumes, I would have thought the Companywide oil number would have been higher. So can you talk about what are -- what could be the offsets to those two areas and how you see the oil mix progressing through the rest of the year?

Yeah. We've guided on the oil growth review, 13% to 19% and I think with that, you get to it 60%, maybe even above 60% oil ratio on a two-stream basis. We feel exceptionally well about that. When you're looking at a quarter, you've got to realize that wells come on at various times throughout the quarter. And so what you're looking at in SpringBoard as it's come on, where we're at now and stuff, it did -- wasn't all on at the beginning of the quarter. So our oil volumes are doing great. You always have -- you asked about adjustments, you always have adjustments like that. We've also got areas, where production was offline or things. It all balances out. I think it is a very normalized number that we reported for the first quarter and it's a good benchmark that carries you forward. So we're in great shape.

Biju Perincheril -- Susquehanna -- Analyst

Got it. And then my follow-up here, thinking about -- of areas that you can step out in existing areas. In the SCOOP, just on southern portions of the SCOOP, in Love County, there's been some pretty good Woodford wells. I think you have had some acreage there. That -- do you still have acreage there? Any plans to test that area?

Jack H. Stark -- President

Yeah. I was going to say that, we've got -- I mean, we have covered a few extra rigs out of SpringBoard and these are some of the work we've been doing down there. I'm not telling you at this moment that we're actually in Love County, but what I'm saying is is we have to build in the option to go ahead and take care of that type of activity. We're -- as you see, there are -- continues to be, I guess, I'd just say some interesting activity in the (inaudible) Montana SCOOP.

Operator

Thank you. And our final question comes from David Meats with Morningstar.

David Meats -- Morningstar -- Analyst

Hey, guys. I'm also interested in those three non-core Bakken wells, which are very impressive. You guys already talked about that this was well cost over there, but I was wondering, particularly in that Montana area, if there's any difference in typical gathering costs or if the average working interest is different out there?

Jack H. Stark -- President

Well, working interests are very high.

Harold G. Hamm -- Chairman and Chief Executive Officer

And they're 100% in the Baird Federal. So average is we're looking at 80%, 90%.

Jack H. Stark -- President

Yeah. I mean -- in our position out there, which is a sizable position and we're looking at 80% to 90% average working. So we're strong.

David Meats -- Morningstar -- Analyst

So that's the working interest. And what about the gathering and transport costs, is there any kind of material difference between those costs out in that Montana area or in the core?

Jack H. Stark -- President

No. We're really not seeing anything anomalous out there on that. I will tell you that the production out there in Montana, though, does have a tax benefit. For the first 18 months, I believe it is that you end up getting your tax reduced down to just 0.5% -- or 1% for the first 18 months. So it is a -- it's a very, very nice bonus that you get for the production that you have out in Montana.

Harold G. Hamm -- Chairman and Chief Executive Officer

It's a production (inaudible) and even that's what developed that earlier to begin with. And certainly, that's what we keep looking at.

David Meats -- Morningstar -- Analyst

Okay. That's good color. And just my quick follow-up here, the -- on the motivation for drilling these wells. It sounds like from your answer to other questions that you're just really testing the back-end of the drilling cube here and just wanted to make sure there's no plans based on these strong results to incorporate these areas more in your near-term development plans?

Jack H. Stark -- President

Well, based on our results, we've got the opportunity to incorporate this into our planned -- compete head-to-head with some of the -- with the inventory that we're drilling. So I mean, what it does is it just essentially gives us a larger playing field here to develop.

David Meats -- Morningstar -- Analyst

All right. Thanks a lot guys. Appreciate the color.

Harold G. Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

Ladies and gentlemen, thank you for participating in today's question-and-answer session. I would now like to turn the call back over to Mr. Rory Sabino for any closing remarks.

Rory Sabino -- Vice President, Investor Relations

Thank you very much for your time today. Please follow up with the IR team here if you have any further questions. Thank you.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may all disconnect and have a wonderful day.

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